It is well known that during the production of hydrocarbons, particularly from gas wells, the accumulation of liquids, primarily water, has presented great challenges to the industry. As the liquid builds at the bottom of the well, a hydrostatic pressure head is built which can become so great as to overcome the natural pressure of the formation or reservoir below, eventually “killing” the well.
A fluid effluent, including liquid and gas, flows from the formation. Liquid accumulates as a result of condensation falling out of the upwardly flowing stream of gas or from seepage from the formation itself. To further complicate the process the formation pressure typically declines over time. Once the pressure has declined sufficiently so that production has been adversely affected, or stopped entirely, the well must either be abandoned or rehabilitated. Most often the choice becomes one of economics, wherein the well is only rehabilitated if the value of the unrecovered resource is greater than the costs to recover it.
A number of techniques have been employed over the years to attempt to rehabilitate wells with diminished reservoir pressure. Some of these are using soap sticks, “pitting” the well occasionally by blowing the well down in a pit to atmospheric pressure, swabbing, injecting high pressure gas into the formation, lowering the end of the tubing string to the perforation, tapering the tubing string to a smaller inner diameter near the surface to increase the flow rate, optimizing tubing size to balance velocity and friction effects, waterflooding the formation to augment pressure depletion, insulating and heating the production tubing string to minimize condensation and liquid fallout and beam lifting.
One common technique has been to shut in or “stop cock” the well to allow the formation pressure to build over time until sufficient to lift the liquids when the well is opened again. Unfortunately, in situations where the formation pressure has declined significantly, it can take many hours to build sufficient pressure to blowdown or lift the liquids, reducing the hours of production. Applicant is aware of wells which must be shut in for 12-18 hours in order to obtain as little as 4 hours of production time before the hydrostatic head again becomes too large to allow viable production.
Two other techniques, plunger and gas lift, are commonly used to enhance production from low pressure reservoirs.
A plunger lift production system typically uses a small cylindrical plunger which travels freely between a location adjacent the formation to a location at the surface. The plunger is allowed to fall to the formation location where it remains until a valve at the surface is opened and the accumulated reservoir pressure is sufficient to lift the plunger and the load of accumulated liquid to the surface. The plunger is typically retained at the wellhead in a vertical section of pipe and associated fitting called a lubricator until such time as the flow of gas is again reduced due to liquid buildup. The valve is closed at the surface which “shuts in” the well. The plunger is allowed to fall to the bottom of the well again and the cycle is repeated. Shut-in times vary depending upon the natural reservoir pressure. The pressure must build sufficiently in order to achieve sufficient energy, which when released, will lift the plunger and the accumulated liquids. As natural reservoir pressure diminishes, the required shut-in times increase, again reducing production times.
Typically, a gas lift production system utilizes injection of compressed gas into production tubing to aerate the production fluids, particularly viscous crude oil, to lower the density and cause the resulting gas/oil mixture to flow more readily to the surface. The gas is typically separated from the oil at the surface, re-compressed and returned to the tubing string. Gas lift methods can be continuous wherein gas is continually added to the tubing string, or gas lift can be performed periodically. In order to supply the large volumes of compressed gas required to perform conventional gas lift, large and expensive systems, requiring large amounts of energy, are required. Gas is typically added to the production tubing using gas lift valves directly tied into the production tubing or optionally, can be added via a second, injection tubing string. Complex crossover elements or multiple standing valves are required for implementations using two tubing strings, which add to the maintenance costs and associated problems.
A combination of gas lift and plunger lift technologies has been employed in which plungers are introduced into gas lift production systems to assist in lifting larger portions of the accumulated fluids. In gas lift alone, the gas propelling the liquid slug up the production tubing can penetrate through the liquid, causing a portion of the liquid to escape back down the well. Plungers have been employed to act as a barrier between the liquid slug and the gas to prevent significant fall down of the liquid. Typically, the plunger is retained at the top of the wellhead during production and then caused to fall only when the well is shut in and the while the annulus is pressurized with gas. This type of combined operation still requires that the well be shut in and production be halted each time the liquid is to be lifted.
Clearly, there is a need, in the case of wells having declining natural reservoir pressure, for apparatus and methods that would allow the energy within the annulus to be augmented for lifting the accumulated liquids in the well, without a requirement to shut in the well and halt production.